Methods and systems employing fiber optic sensors for electromagnetic cross-well telemetry

ABSTRACT

A system includes a drillstring with an electromagnetic (EM) transmitter in a first borehole. The system also includes at least one fiber optic sensor deployed in a second borehole. The system also includes a processor configured to demodulate a data stream emitted by the EM transmitter based on EM field measurements collected by the at least one fiber optic sensor.

BACKGROUND

The world depends on hydrocarbons to solve many of its energy needs.Consequently, oil field operators strive to produce and sellhydrocarbons as efficiently as possible. Much of the easily obtainableoil has already been produced, so new techniques are being developed toextract less accessible hydrocarbons. One such technique issteam-assisted gravity drainage (“SAGD”) as described in U.S. Pat. No.6,257,334, “Steam-Assisted Gravity Drainage Heavy Oil Recovery Process”.SAGD uses a pair of vertically-spaced, horizontal wells less than about10 meters apart.

In operation, the upper well is used to inject steam into the formation.The steam heats the heavy oil, thereby increasing its mobility. The warmoil (and condensed steam) drains into the lower well and flows to thesurface. A throttling technique is used to keep the lower well fullyimmersed in liquid, thereby “trapping” the steam in the formation. Ifthe liquid level falls too low, the steam flows directly from the upperwell to the lower well, reducing the heating efficiency and inhibitingproduction of the heavy oil. Such a direct flow (termed a “shortcircuit”) greatly reduces the pressure gradient that drives fluid intothe lower well.

Short circuit vulnerability can be reduced by carefully maintaining theinter-well spacing, i.e., by making the wells as parallel as possible.(Points where the inter-well spacing is smaller than average providelower resistance to short circuit flows.) In the absence of precisiondrilling techniques, drillers are forced to employ larger inter-wellspacings than would otherwise be desirable, so as to reduce the effectsof inter-well spacing variations. Precision placement of neighboringwells is also important in other applications, such as collisionavoidance, infill drilling, observation well placement, coal bed methanedegasification, and wellbore intersections. Unfortunately, the rangingoperations needed to achieve precision placement of neighboring wellsare costly and time-consuming. Further, to the extent communicationsbetween a bottomhole assembly (BHA) and earth's surface are limited,directional drilling decisions are delayed and/or are based onincomplete information.

BRIEF DESCRIPTION OF THE DRAWINGS

Accordingly, there are disclosed in the drawings and the followingdescription methods and systems employing fiber optic sensors forcross-well telemetry. In the drawings:

FIG. 1 is a schematic diagram showing an illustrative cross-welltelemetry scenario.

FIGS. 2A-2E are schematic diagram showing illustrative fiber opticsensor deployment options.

FIG. 3 is a schematic diagram showing an arrangement of fiber opticsensors for cross-well telemetry.

FIG. 4A is a perspective view of a fiber optic sensor unit forcross-well telemetry.

FIG. 4B is a cross-sectional view of the fiber optic sensor unit of FIG.3A.

FIG. 5 is a schematic diagram showing an illustrative opticalinterrogation system.

FIG. 6 is a graph showing illustrative magnetic field measurementcharacteristics.

FIG. 7 is a flowchart showing an illustrative cross-well telemetrymethod employing fiber optic sensors.

It should be understood, however, that the specific embodiments given inthe drawings and detailed description do not limit the disclosure. Onthe contrary, they provide the foundation for one of ordinary skill todiscern the alternative forms, equivalents, and modifications that areencompassed together with one or more of the given embodiments in thescope of the appended claims.

DETAILED DESCRIPTION

Disclosed herein are methods and systems employing fiber optic sensorsfor electromagnetic (EM) cross-well telemetry. An example methodincludes emitting a data stream by an EM transmitter in a firstborehole. The method also includes obtaining EM field measurements inresponse to the emitted EM field using an array of fiber optic sensorsdeployed in a second borehole. The method also includes demodulating thedata stream based on the EM field measurements. A related systemincludes a drillstring with an EM transmitter in a first borehole. Thesystem also includes an array of fiber optic sensors deployed in asecond borehole. The system also includes a processor configured todemodulate a data stream emitted by the EM transmitter based on EM fieldmeasurements collected by one or more of the fiber optic sensors.

In at least some embodiments, the EM transmitter may be part of alogging-while-drilling (LWD) tool. In such case, the EM transmitter canhave multiple roles. For example, in one role, the EM transmitter isused for cross-well telemetry operations. In another role, the EMtransmitter is used to collect EM survey data. In yet another role, theEM transmitter may be used for ranging operations. Similarly, the fiberoptic sensors may be deployed along a fiber optic cable that servesmultiple roles. For example, in one role, the fiber optic cable is usedto convey EM field measurements for cross-well telemetry. In anotherrole, the fiber optic cable is used to collect distributed sensingmeasurements related to pressure, temperature, chemicals, or acousticactivity. In yet another role, the fiber optic cable may be used toconvey EM field measurements used for ranging. Other roles are possible.Further, the fiber optic sensors can have multiple roles. In one role,the fiber optic sensors collect EM field measurements for cross-welltelemetry. In another role, the fiber optic sensors collect EM fieldmeasurements for ranging operations. In yet another role, the fiberoptic sensors collect EM survey data (e.g., during production orreservoir monitoring operations). Using cross-well telemetry systemcomponents in multiple roles (or using logging/sensing system componentsfor cross-well telemetry) as described herein decreases the overall costcompared to using separate systems. Various component role options,fiber optic sensor options, sensor placement options, and cross-welltelemetry options are disclosed herein.

FIG. 1 shows an illustrative cross-well telemetry scenario. In FIG. 1, adrilling assembly 12 enables a drillstring 30 to be lowered and raisedin a borehole 22A that penetrates formations 21 of the earth 20. Thedrillstring 30 includes a plurality of drillstring segments 32 joined bycollars or adaptors 34. At the lower end of the drill string 30, abottomhole assembly 24 (BHA) with a drill bit 25 removes material andpenetrates the formations 21 using known drilling techniques. The BHA 24may include, for example, thick-walled tubulars called drill collars,which add weight and rigidity to aid the drilling process. The thickwalls of these drill collars make them useful for housinginstrumentation and LWD sensors. In at least some embodiments, the BHA24 includes a logging tool 26 with at least one EM transmitter 27 and atelemetry/control unit 28. The EM transmitter 27 may be axially orientedas shown or may be tilted relative to the longitudinal axis of the BHA24. If multiple EM transmitters are used, their position and/ororientation may vary. In at least some embodiments, the EM transmitter27 emits rotationally invariant EM signals at one or more frequencies(e.g., 100 Hz, 10 kHz, etc.). In this manner, the EM transmitter 27 canbe rotated as part of the BHA 24 without degrading cross-well telemetrysignals. For example, an EM transmitter 27 that is axially orientedwould emit rotationally invariant EM signals.

The logging tool 26 may also include one or more EM field sensor units(not shown) to collect EM survey data in response to EM fields emittedby the EM transmitter 27 and/or ambient EM fields. The telemetry/controlunit 28 includes electronics for data storage, communication, etc. Thus,the EM survey data collected by the logging tool 26 may be conveyed toearth's surface and/or is stored by the logging tool 36. In either case,the EM survey data can later be analyzed as a function of positionand/or time to determine properties of the formations 19. For example,the EM survey data may be used to derive a permeability log as afunction of position, to track movement of downhole fluids, and/ormonitor other formation properties. The logs and/or formation propertiesderived from EM survey data may be displayed to an operator via computer40.

In at least some embodiments, an interface 14 at earth's surfacereceives EM survey data or other survey data from the BHA 24 via knowntelemetry techniques (e.g., mud pulse telemetry, acoustic telemetry, orEM telemetry). The surface interface 14 and/or a computer system 40 mayperform various operations such as converting received signals from oneformat to another, storing survey data, processing survey data, derivinglogs from the survey data, and/or displaying logs or other visualizationof survey data. Meanwhile, another interface 16 at earth's surface forborehole 22B receives cross-well telemetry data from the fiber opticsensors 38 deployed along the fiber optic cable 36. In differentembodiments, the cross-well telemetry data supplements or replaces othertelemetry techniques.

The interface 16 may also include optical interrogation components forcollecting cross-well telemetry data from the fiber optic sensors 38.The surface interface 16 and/or a computer system 40 may perform variousoperations such as converting received signals from one format toanother, demodulating cross-well telemetry data, storing cross-welltelemetry data, processing cross-well telemetry data, deriving logs fromthe cross-well telemetry data, and/or displaying a representation of theBHA's position or other visualizations related to the cross-welltelemetry data. While the interfaces 14 and 16 are shown to be separate,it should be appreciated that at least some functions of the interfaces14 and 16 could be combined. Further, the computer 40 may be used tostore, process, and visualize ranging data, EM survey data, and/orcross-well telemetry data. Alternatively, one or more computers may beemployed for EM survey data or ranging data processing andvisualization, while one or more other computers are employed forcross-well telemetry data processing and visualization.

In at least some embodiments, the computer system 40 includes aprocessing unit 42 that processes cross-well telemetry data by executingsoftware or instructions obtained from a local or remote non-transitorycomputer-readable medium 48. The computer system 40 also may includeinput device(s) 46 (e.g., a keyboard, mouse, touchpad, etc.) and outputdevice(s) 44 (e.g., a monitor, printer, etc.). Such input device(s) 46and/or output device(s) 44 provide a user interface that enables anoperator to interact with the logging tool 26 and/or software executedby the processing unit 42. For example, the computer system 20 mayenable an operator may select cross-well telemetry data analysisoptions, to view collected cross-well telemetry data, to view cross-welltelemetry data analysis results, and/or to perform other tasks.

To perform cross-well telemetry operations, the EM transmitter 27 emitsan EM field 35 that is modulated to convey a data stream. Variousmodulation techniques are possible (e.g., amplitude modulation,frequency modulation, phase modulation, pulse modulation). The datastream may correspond to raw sensor data, processed data, compresseddata, or a combination of different types of data. The EM field 35 issensed by one or more fiber optic sensors 38 that are part of an array37 of such sensors 38 deployed in a borehole 22B nearby borehole 22A.While not shown, it should be appreciated that the borehole 22B maycorrespond to a completed well with casing that has been cemented inplace. In such case, the fiber optic sensors 38 may be permanentlydeployed as part of the well completion process for borehole 22B. Forexample, each fiber optic sensor 38 may be attached to the exterior of acasing segment by one or more bands or other attachment mechanism. Oncethe casing is cemented in place, the fiber optic sensors 38 and thefiber optic cable 36 will likewise be cemented in place and will enableongoing sensing and cross-well telemetry operations. In alternativeembodiments, the borehole 22B may correspond to an open well orpartially completed well. In such case, the fiber optic sensors 38 maybe deployed along an open section in the borehole 22B using wirelineand/or pump down operations. Further, in at least some embodiments, thesensitivity of the fiber optic sensors 38 and the EM properties of theborehole fluid and casing may allow for temporary deployment of thefiber optic sensors 38 inside a casing. In such case, wireline and/orpump down operations may enable the fiber optic sensors 38 to bedeployed inside a cased section of the borehole 22B. Further, the EMtransmitter 27 may be directed to emit EM signals at a lower frequency(e.g., 100 Hz) and/or higher transmitter moments to reduce the affect ofthe casing on the EM field measurements. As desired, the fiber opticcable 36 and fiber optics sensors 38 used for a temporary deploymentscenario may be retrieved and deployed in another well.

The EM field measurements collected by one or more sensors 38 in thearray 37 are conveyed to earth's surface via the fiber optic cable 36,which includes one or more optical fibers. It should be appreciated thatthe spacing of sensors 38 along the fiber optic cable 36 may vary.Further, the manner in which each sensor 38 is coupled to an opticalfiber of the fiber optic cable 36 may vary. The availability of multipleoptical fibers, optical couplers, and/or reflective components supportvarious options for coupling each fiber optic sensor 38 to the fiberoptic cable 36. In operation, the fiber optic sensors 38 generate lightin response to an EM field or modulate the intensity or phase ofinterrogation (source) light in response to an EM field. The generatedor modulated light from a given fiber optic sensor 38 providesinformation regarding the modulated EM field sensed by that given sensor38. As desired, time division multiplexing (TDM), wavelength divisionmultiplexing (WDM), mode-division multiplexing (MDM) and/or othermultiplexing options may be used to recover the measurements associatedwith each fiber optic sensor 38 deployed along fiber optic cable 36.

In accordance with at some embodiments, the processing unit 42 ofcomputer 40 or circuitry in interface 16 demodulates a data streamobtained from cross-well telemetry, where EM field measurements arecollected by one or more of the fiber optic sensors 38. As an example,in order to recover a data stream of 1000 bits/second, it should beappreciated that the sampling rate for the EM field measurementscollected by one or more of the fiber optic sensors 38 must be at least1000 bits/second. Further, knowledge regarding the particular modulationscheme being used is needed to demodulate a data stream obtained fromcross-well telemetry. Demodulation may also be facilitated by knowingthe position of the EM transmitter 27 relative to one or more of thefiber optic sensors 38. Further, the orientation of one or more EMtransmitter 27 and/or the orientation of the fiber optic sensors 38 maybe selected so as to increase the signal-to-noise ratio (SNR) and/orrange of cross-well telemetry. Further, the fiber optic cable 36 may beshielded to decrease the amount of interference affecting EM fieldmeasurements conveyed along the fiber optic cable 36. Further, aninversion algorithm based on rules or laws governing EM fields may beused to account for how the downhole environments affects the EM fieldemitted by the EM transmitter 27. The inversion algorithm may be basedon deterministic and/or stochastic methods of optimization. In at leastsome embodiments, an anisotropic resistivity model is used for theinversion algorithm. This anisotropic resistivity model can beconstructed a priori from seismic data (e.g., 2D/3D/4D seismic surveydata, vertical seismic profiling (VSP) survey data, seismicinterferometry, acoustic logs, etc.) and/or resistivity data (e.g.,resistivity logs obtained from LWD and/or wireline tools). To constructan anisotropic resistivity model, computational algorithms (e.g., welltying or geostatistics) for accurate model constructions may beemployed. The anisotropic resistivity model may be 1D, 2D, or 3D. Formore information regarding general modeling and inversion algorithmsapplicable to EM survey data, reference may be had to D. B. Avdeev,2005, “Three-dimensional electromagnetic modeling and inversion fromtheory to application”, Surveys in Geophysics, volume 26, pp. 767-799.

The demodulated cross-well telemetry data stream obtained by computer 40or another processing system provides information regarding the downholeenvironment and/or BHA/drilling operations. Example uses of thedemodulated cross-well telemetry data stream include, but are notlimited to, visualization of the BHA position in the downholeenvironment, visualization of logged parameters as a function ofposition in the downhole environment, directional drilling guidance. Iftrajectory updates for the borehole 22A are needed in view ofdemodulated cross-well telemetry data stream or ranging data, adirectional drilling controller (e.g., the computer 40 or anothercontroller) is able to direct steering components of the BHA 24. Examplesteering mechanisms include steering vanes, a “bent sub,” and a rotarysteerable system.

FIGS. 2A-2E show illustrative fiber optic sensor deployment options. Forthe deployment options represented in FIGS. 2A-2E, the fiber opticsensors 38 are spaced along the fiber optic cable 36 exterior to casing60. In FIG. 2A, spaced bands 62 are placed around the casing 60 to holdthe fiber optic sensors 38 and fiber optic cable 36 in place. In FIG.2B, the fiber optic sensors 38 are mounted on swellable packers 66. Suchpackers 66 expand when exposed to downhole conditions, pressing thesensors 38 into contact with the borehole wall. Additionally oralternatively, fins or spacers may be used to space fiber optic sensors38 away from the casing 60. In FIG. 2C, bow-spring centralizers 68 areused to press the sensors 38 into contact with the borehole walls. Tominimize insertion difficulties, a restraining mechanism may hold thespring arms of the bow-spring centralizers 68 against the casing 60until the casing 60 has been inserted in a corresponding borehole.Thereafter, exposure to downhole conditions or a circulated fluid (e.g.,an acid) degrades the restraining mechanism and enables the spring armsof each bow-spring centralizers 68 to extend the sensors 38 against aborehole wall. While only one fiber optic cable 36 is shown in FIGS.2A-2C, it should be appreciated that multiple fiber optic cables 36 andcorresponding sensors could be deployed along casing 60. The use ofmultiple fiber optic cables 36 and corresponding sensors along casing isone way to increase directional sensitivity for cross-well telemetryand/or other sensing operations.

Other extension mechanisms are known in the oilfield and may be suitablefor placing the sensors 38 in contact with the borehole wall or intosome other desired arrangements such as those illustrated in FIG. 2D and2E. In FIG. 2D, multiple fiber optic cables 36 with sensors 38 (notshown) are distributed in the annular space between the casing 60 and aborehole wall 70. In FIG. 2E, the fiber optic cables 36 andcorresponding sensors 38 (not shown) have a distribution with axial,azimuthal, and radial variation. The annular space between the casing 60and the borehole wall 70 could be filled with cement for a morepermanent sensor installation. Balloons, hydraulic arms, and projectilesare other contemplated mechanisms for positioning the sensors 38.Besides ensuring that the fiber optic sensors 38 are exposed to the EMfield 35 emitted by the EM transmitter 27, it should be appreciated thatthe particular position and orientation of the sensors 38 in thedownhole environment can be considered for cross-well telemetry (to helpmaximize SNR, bandwidth, communication range, etc.). Accordingly,position sensors, orientation sensors, predetermined informationregarding a borehole trajectory, and/or sensor spacing may be used toestimate a fiber optic sensor's position.

FIG. 3 shows an illustrative arrangement of EM field sensors. Morespecifically, each of a plurality of EM field sensor groups 72A-72Ncouples to fiber optic cable 36 and can collect EM field measurements asdescribed herein. In at least some embodiments, each of the sensorgroups 72A-72N may include orthogonal EM field sensors 38 _(A), 38 _(B),38 _(C) (not shown for groups 72B-72N), where sensor 38 _(A) is orientedalong the z-axis, sensor 38 _(B) is oriented along the x-axis, andsensor 38 _(C) is oriented along the y-axis. The generated or modulatedlight output from each of the EM field sensors 38 _(A), 38 _(B), 38 _(C)is conveyed to a surface interface (e.g., interface 16) via fiber opticcable 36, where its characteristics can be converted to an electricalsignal and interpreted to decode a data stream included in the EM fieldsensed by one or more of the sensors 38 _(A), 38 _(B), 38 _(C) in sensorgroups 72A-72N. Due to boreholes having trajectories that vary (e.g.,vertical and horizontal sections are common), it should be appreciatedthat the orientation of different sensors 38 _(A), 38 _(B), 38 _(C) fordifferent sensor groups 72A-72N may vary depending on where a givensensor group is relative a varying borehole trajectory. In general, thesensors 38 _(A), 38 _(B), 38 _(C) for a given sensor group areorthogonal to each other, but their particular orientation may varyrelative to the sensors in other sensor groups. While multiple sensors38 are represented for each of the sensor groups 72A-72N, it should beappreciated that individual sensors 38 could be spaced along the fiberoptic cable 36. In either case, the particular orientation of individualsensors 38 or sensor groups 72 can affect cross-well telemetry (SNR,bandwidth, communication range, etc.) and may be accounted by carefulplanning and deployment of the sensors 38 or sensor groups 72 and/or byproviding an EM transmitter configuration with multiple orientationoptions.

FIG. 4A shows a cutaway view of a fiber optic sensor unit 100.Meanwhile, FIG. 4B shows a cross-sectional view of the field opticsensor unit 100. The fiber optic sensor unit 100 is an example of afiber optic sensor 38. In both FIGS. 4A and 4B, an optical fiber 114extends through opposite ends of housing 102. In at least someembodiments, the housing 102 has a hollow cylindrical shape as shown,although other hollow shapes are possible (e.g., rectangular or boxshape). Within the housing 102, an EM field sensor 110 and an opticaltransducer 112 operate to generate a light beam or to modulate a sourcelight beam in presence of an EM field. For example, in one embodiment,the EM field sensor 110 and optical transducer 112 correspond to anelectrostrictive or magnetostrictive component bonded to optical fiber114. In this configuration, the EM field sensor 110 and opticaltransducer 112 are combined to form an electro-optical transducer ormagneto-optical transducer that directly strains or otherwise changesthe condition of the optical fiber 114 in presence of an EM field. Forthe above examples, the electrostrictive or magnetostrictive componentcould be considered an EM field sensor 110, while the bond between theelectrostrictive or magnetostrictive component and the optical fiber 114could be considered an optical transducer. As used herein, the term“bonded” refers to any physical or adhesive-based connection such thatdeformation of the magnetostrictive component causes a correspondingstrain to the optical fiber 114. Using an electrostrictive ormagnetostrictive component to jacket optical fiber 114 such that theoptical fiber 114 is strained in response to deformation of theelectrostrictive or magnetostrictive component is an example of asuitable bond.

The above electro-optical transducer and magneto-optical transducerconfigurations are suitable for optical interrogation, where a sourcelight beam in the optical fiber 114 is modulated by the amount of strainapplied to the optical fiber 114 by the electrostrictive ormagnetostrictive component in presence of an EM field. Another exampleof electro-optical transducer and magneto-optical transducerconfigurations involve wrapping optical fiber 114 around anelectrostrictive or magnetostrictive component (e.g., a cylinder) suchthat a source light beam conveyed along the optical fiber 114 ismodulated by the amount of strain applied to the optical fiber 114 bythe electrostrictive or magnetostrictive component in presence of an EMfield.

In another embodiment, the EM field sensor 110 corresponds to aninductive coil, where a voltage is induced in the coil in presence of amagnetic field. In such case, the optical transducer 112 may correspondto a light-emitting diode (LED) configuration suitable for opticalmonitoring operations. Alternatively, configurations suitable foroptical interrogation operations may employ an optical transducer 112that modulates a source light beam based on a voltage induced in a coilby a magnetic field. Some example optical transducers 112 suitable formodulating a source light beam based on an induced voltage include: 1) apiezoelectric component bonded to a fiber laser; 2) a hinged reflectivesurface; 3) a piezoelectric component that bends or strains an opticalfiber; 4) an optical resonator; and 5) a lithium niobate modulator.While the above EM field sensor examples are able to detect magneticfield variations, it should be appreciated that other EM field sensorsmay be configured to detect electric field variations.

In at least some embodiments, each fiber optic sensor unit 100 can beconfigured to measure the triaxial electric and/or magnetic fields. Insome embodiments, the magnetic field sensor can consist of an opticalfiber bonded to or jacketed by a magnetorestrictive material. Somecommon magnetostrictive materials include cobalt, nickel, and ironmetals, and their alloys, e.g., Metglass and Terfenol-D. When exposed toa time-varying magnetic field, the deformation (i.e., change in shape)in the magnetorestrictive material induces a strain on the opticalfiber, which can be remotely interrograted using any of the fiber-opticstrain measurement methods including but not limited to inteferometric,fiber Bragg grating (FBG), fiber laser strain (FLS), and extrinsicFabry-Perot interferometric (EFPI) methods. The strain is proportionalto the applied magnetic field. In at least some embodiments, the sensoris operated such that the strain is linearly proportional to the appliedmagnetic field.

In recent experiments in which magnetic field sensors were characterizedfor permanent deployment in waterflood monitoring, the minimumdetectable magnetic field required to drive Terfenol-D or Metglasmagnetorestriction is approximately 30-40 μA/m. In other embodiments, anelectric field sensor may include an optical fiber bonded to or jacketedby an electrorestrictive material. Some common electrorestrictivematerials include lithium niobate and PZT. When the earth's potentialsensed between an electrode pair is applied to the electrorestrictivematerial, the deformation (i.e., change in shape) in theelectrorestrictive material induces a strain on the optical fiber, whichcan be remotely interrograted using fiber-optic strain measurementmethods such as inteferometric, FBG, FLS, and EFPI methods. In at leastsome embodiments, the strain is proportional to the applied electricfield. For example, the sensor may operate such that the strain islinearly proportional to the earth's potential field. In recentexperiments in which electric field sensors where characterized forpermanent deployment in waterflood monitoring, the minimum detectablepotential difference required between an electrode pair to drive PZTelectrorestriction is approximately 1 μV.

In different embodiments, each fiber optic sensor unit 100 may includeone EM field sensor 110 as shown or may include multiple EM fieldsensors 110. In other words, each fiber optic sensor unit 100 can beconstructed to measure one, two, or three directional components of anEM field. In addition to having one or more EM field sensors 110, eachfiber optic sensor unit 100 may include one or more optical transducers112 placed within a single sensor unit housing. In such case, thecomponent orientation (e.g., orthogonal, collinear) and/or position(e.g., staggered) may vary to ensure at least one EM field sensor isoriented to enable cross-well telemetry.

When assembling a fiber optic sensor unit 100, the housing 102 may haveat least two parts. For example, one of the ends of the housing 102 mayinitially be open to allow the EM field sensor 110, the opticaltransducer 112, and the optical fiber 114 to be positioned inside thehousing 102. Once the EM field sensor 110, the optical transducer 112,and the optical fiber 114 are positioned as desired, an end cap 116 witha hole for the optical fiber 114 and/or connecter 104 is added to coverthe open end of the housing 102. The end cap 116 may be coupled to therest of the housing 102 using welds, threads, adhesive, etc.

In at least some embodiments, the housing 102 provides space 108 aroundthe EM field sensor 110 and/or optical transducer 112 so that the EMfield sensor 110 and/or optical transducer 112 are free to deform inpresence of an EM field. Without limitation to other embodiments, anexample fiber optic sensor unit 100 has a maximum width of about 1 inch,a housing thickness of about 2 mm, and a maximum length of about 4inches. A plurality of such fiber optic sensor units 100 may be added(e.g., via splicing) to a tubing encapsulated cable (TEC), whichtypically have an outer diameter of approximately 1 cm. When assembly iscomplete, a modified TEC with distributed fiber optic sensor units 100may be deployed downhole in a cross-well telemetry environment asdescribed herein.

In at least some embodiments, the housing 102 includes connectors 104 atopposite ends where the optical fiber 114 extends through the housing102. For example, the connectors 104 may be part of the housing and/orend caps 116. Alternatively, the connectors 104 may be added to end cap116 using welds, threads, adhesive, sealants, etc. The connectors 104enable a fiber optic sensor unit 100 to couple to a cable (e.g., cable36). As an example, the connector 104 may be threaded or otherwiseconfigured to mate with a corresponding connector of a cable. Inaddition, the optical fiber 114 extending from the housing 102 atopposite ends may be spliced with optical fibers of a cable to form acontinuous optical waveguide. Available splicing techniques may beemployed to create a fiber optic cable (e.g., cable 36) with a pluralityof such sensor units 100 distributed along the length of the cable. Formore information regarding fiber optic sensor housing options (size,material, wall thickness) and fill options, reference may be had toPCT/US2014/038552, entitled “Optical Magnetic Field Sensor Units for aDownhole Environment” and filed May 19, 2014.

In at least some embodiments, the fiber optic sensor units 100 can befabricated in such a manner to enable efficient mass production and easeof deployment as part of a permanent EM monitoring system. For example,sensor units 100 and a corresponding cable (e.g., cable 36) can bepre-fabricated in a factory and delivered on a cable reel for ease ofdeployment at the well site during the completion of a well. Across-well telemetry system employing sensor units 100 can besimultaneously deployed with other fiber optic-based sensors including,but not limited to, acoustic sensors, temperature sensors, pressuresensors, strain sensors, chemical sensors, current sensors and/orelectric field sensors.

In accordance with at least some embodiments, a plurality of fiber opticsensor units 100 can be deployed along the same optical fiber andinterrogated or monitored through at least one method of multiplexing.FIG. 5 shows an illustrative optical interrogation system 200. In system200, various fiber optic sensor units 100 are distributed along opticalfiber(s) 208 or a corresponding cable (e.g., cable 36). The opticalfiber(s) 208 is coupled to a laser 202 and a detector 204 via a coupler206. In at least some embodiments, the laser 202 and the detector 204are part of an interrogation interface (e.g., interface 16 of FIG. 1).In operation, one or more of the fiber optic sensor units 100 modulatesource light beams emitted by the laser 202 in accordance with an EMfield present at the location of each of the sensor units 100.

The detector 204 receives the modulated source light beams and recoversEM field measurements that convey a data stream as described herein. Thelaser 202, the detector 204, the fiber optic sensor units 100, and/orthe optical fiber(s) 208 may be configured for multiplexing options suchas TDM, WDM, and/or MDM. In principle the number of fiber optic sensorunits 100 in system 200 is only limited by the attenuation of lightpropagating along the optical fiber(s) 208. Certain contemplatedembodiments include hundreds of fiber optic sensor units 100 along agiven optical fiber 208.

FIG. 6 is a graph 300 showing illustrative magnetic field measurementcharacteristics. For the measurements of FIG. 6, an x-directed EMtransmitter having a 10 turn loop antenna with diameter of 7″, andoperated at 1 kHz with a current of 0.5 A is assumed. Further, theeffective permeability of the loop antenna core is that of free space,and the range of the EM transmitter varies from 5 meters to 7 metersabove an array of x-directed fiber optic sensors. Further, the formationis assumed to have a uniform resistivity of 10 ohm-m. For a range of 5meters, magnetic fields are detectable ±10 meters (i.e., a lateraloffset of 10 meters or less results in magnetic field amplitudes of30-40 μA/M from the EM transmitter). For a range of 7 meters, magneticfields are detectable ±7 meters (i.e., a lateral offset of 7 meters orless results in magnetic field amplitudes of 30-40 μA/M) from the EMtransmitter). Thus, if fiber optic sensors (e.g., sensors 38 or sensorunits 100) are placed, for example, every 10 meters (30 feet or so)along a borehole (e.g., borehole 22B), the EM fields transmitted by anEM transmitter (e.g., transmitter 27) in a nearby borehole (e.g.,borehole 22A) would be detected by at least two of the fiber opticsensors.

FIG. 7 is a flowchart showing an illustrative cross-well telemetrymethod 400 employing fiber optic sensors. In the method 400, a firstwell is drilled at block 402. At block 404, at least one fiber opticsensor is deployed in the first well. The at least one fiber opticsensor may be deployed temporarily or permanently as described herein.At block 406, a second well is drilled. At block 408, a data stream isemitted by from an EM transmitter in the second well. At block 410, EMfields signals emitted from the EM transmitter in the second well aremeasured by the at least one fiber optic sensor in the first well. TheEM field measurements include the data stream and are conveyed toearth's surface for storage and processing as described herein. At block412, the data stream is demodulated using the measured EM field signals.At block 414, information is stored or displayed based on thedemodulated data stream. For example, the demodulated data stream may beused for visualization of the BHA position in the downhole environment,visualization of logged parameters as a function of position in thedownhole environment, directional drilling guidance, and/or otheroperations.

In at least some embodiments, the cross-well telemetry method 400 may beperformed using components that have a dual role. For example, the EMtransmitter may be used for the cross-well telemetry operationsdescribed herein as well as for collecting EM survey data or rangingdata. Such EM survey data provides information about the EM propertiesof a formation and/or can track the movement of fluid in a formation,etc.

Meanwhile, ranging data can be used for directional drilling guidance.Further, the fiber optic cable coupled to the fiber optic sensors may beused to convey EM field measurements used for cross-well telemetry asdescribed herein as well as for collecting distributed sensingparameters such as temperature, pressure, acoustic activity, or otherdownhole parameters. Further, the fiber optic cable may be used toconvey EM field measurements used for ranging operations. Further, thefiber optics sensors could be used to perform the cross-well telemetryoperations as described herein as well as to collect EM survey data(e.g., during production and reservoir monitoring operations) or rangingmeasurements. By using components with a dual role, the overall cost ofdata collection and telemetry operations is reduced compared to usingseparate systems.

Embodiments disclosed herein include:

A: A system that comprises a drillstring with an electromagnetic (EM)transmitter in a first borehole, at least one fiber optic sensordeployed in a second borehole, and a processor configured to demodulatea data stream emitted by the EM transmitter based on EM fieldmeasurements collected by the at least one fiber optic sensor.

B. A method that comprises emitting a data stream by an EM transmitterin a first borehole, obtaining EM field measurements corresponding tothe data stream using at least one fiber optic sensor deployed in asecond borehole, and demodulating the data stream based on the EM fieldmeasurements.

Each of the embodiments, A and B, may have one or more of the followingadditional elements in any combination. Element 1: further comprising adirectional drilling controller configured to update a trajectory forthe first borehole based at least in part on information conveyed in thedata stream. Element 2: further comprising a monitor in communicationwith the processor, wherein the monitor displays formation propertiesbased at least in part on information conveyed in the data stream.Element 3: wherein the at least one fiber optic sensor is permanentlydeployed downhole along a fiber optic cable that extends along a casingexterior in the second borehole. Element 4: wherein the at least onefiber optic sensor is temporarily deployed downhole along a fiber opticcable that extends inside a casing in the second borehole. Element 5:wherein the at least one fiber optic sensor is deployed along a fiberoptic cable used for distributed sensing of temperature, pressure,chemicals, or acoustic activity. Element 6: wherein the at least onefiber optic sensor resides within a protective housing. Element 7:wherein the at least one fiber optic sensor comprises a magnetic fieldsensor. Element 8: wherein the at least one of fiber optic sensorcomprises an electric field sensor. Element 9: wherein the EMtransmitter is part of a bottomhole assembly (BHA), and wherein the EMtransmitter is used to collect EM survey data and for cross-welltelemetry.

Element 10: further comprising updating a drilling trajectory for thefirst borehole based at least in part on information conveyed in thedata stream. Element 11: further comprising displaying formationproperties based at least in part on information conveyed in the datastream. Element 12: further comprising permanently deploying the atleast one fiber optic sensor downhole along a fiber optic cable thatextends along a casing exterior in the second borehole. Element 13:further comprising temporarily deploying the at least one fiber opticsensor downhole along a fiber optic cable that extends inside a casingin the second borehole. Element 14: further comprising deploying the atleast one fiber optic sensor downhole along a fiber optic cable used fordistributed sensing of temperature, pressure, chemicals, or acousticactivity. Element 15: further comprising deploying the at least onefiber optic sensor downhole to have a predetermined orientation relativeto the EM transmitter. Element 16: wherein obtaining EM fieldmeasurements comprises outputting a voltage in response to a magneticfield corresponding to an EM field emitted by the EM transmitter, andemitting a light based on the voltage or modulating an interrogationlight based on the voltage. Element 17: wherein obtaining EM fieldmeasurements comprises outputting a voltage in response to an electricfield corresponding to the EM field emitted by the EM transmitter, andemitting a light based on the voltage or modulating an interrogationlight based on the voltage. Element 18: further comprising using the EMantenna to collect EM survey data and to perform cross-well telemetry.

Numerous variations and modifications will become apparent to thoseskilled in the art once the above disclosure is fully appreciated. Theensuing claims are intended to cover such variations where applicable.

What is claimed is:
 1. A system that comprises: a drillstring with anelectromagnetic (EM) transmitter in a first borehole; at least one fiberoptic sensor deployed in a second borehole; and a processor configuredto demodulate a data stream emitted by the EM transmitter based on EMfield measurements collected by the at least one fiber optic sensor. 2.The system of claim 1, further comprising a directional drillingcontroller configured to update a trajectory for the first boreholebased at least in part on information conveyed in the data stream. 3.The system of claim 1, further comprising a monitor in communicationwith the processor, wherein the monitor displays formation propertiesbased at least in part on information conveyed in the data stream. 4.The system of claim 1, wherein the at least one fiber optic sensor ispermanently deployed downhole along a fiber optic cable that extendsalong a casing exterior in the second borehole.
 5. The system of claim1, wherein the at least one fiber optic sensor is temporarily deployeddownhole along a fiber optic cable that extends inside a casing in thesecond borehole.
 6. The system of claim 1, wherein the at least onefiber optic sensor is deployed along a fiber optic cable used fordistributed sensing of temperature, pressure, chemicals, or acousticactivity.
 7. The system of claim 1, wherein the at least one of thefiber optic sensor resides within a protective housing.
 8. The system ofclaim 1, wherein the at least one of the fiber optic sensor comprises amagnetic field sensor.
 9. The system of claim 1, wherein the at leastone of the fiber optic sensor comprises an electric field sensor. 10.The system of claim 1, wherein the EM transmitter is part of abottomhole assembly (BHA), and wherein the EM transmitter is used tocollect EM survey data and for cross-well telemetry.
 11. A method thatcomprises: emitting a data stream by an EM transmitter in a firstborehole; obtaining EM field measurements corresponding to the datastream using at least one fiber optic sensor deployed in a secondborehole; and demodulating the data stream based on the EM fieldmeasurements.
 12. The method of claim 11, further comprising updating adrilling trajectory for the first borehole based at least in part oninformation conveyed in the data stream.
 13. The method of claim 11,further comprising displaying formation properties based at least inpart on information conveyed in the data stream.
 14. The method of claim11, further comprising permanently deploying the at least one fiberoptic sensor downhole along a fiber optic cable that extends along acasing exterior in the second borehole.
 15. The method of claim 11,further comprising temporarily deploying the at least one fiber opticsensor downhole along a fiber optic cable that extends inside a casingin the second borehole.
 16. The method of claim 11, further comprisingdeploying the at least one fiber optic sensor downhole along a fiberoptic cable used for distributed sensing of temperature, pressure,chemicals, or acoustic activity.
 17. The method of claim 11, furthercomprising deploying the at least one fiber optic sensor downhole tohave a predetermined orientation relative to the EM transmitter.
 18. Themethod of claim 11, wherein obtaining EM field measurements comprises:outputting a voltage in response to a magnetic field corresponding to anEM field emitted by the EM transmitter, and emitting a light based onthe voltage or modulating an interrogation light based on the voltage.19. The method of claim 11, wherein obtaining EM field measurementscomprises: outputting a voltage in response to an electric fieldcorresponding to the EM field emitted by the EM transmitter, andemitting a light based on the voltage or modulating an interrogationlight based on the voltage.
 20. The method of claim 11, furthercomprising using the EM antenna to collect EM survey data and to performcross-well telemetry.